Drilling procedures for hydrocarbon-producing wells often include lining the wellbore with one or more casings to provide structural integrity to the wellbore and/or to isolate various portions of the subterranean formation, e.g. groundwater reservoirs, pay zones, etc. Generally, wellbore casings are composed of a plurality of casing pipe segments (casing joints) that are attached to form a cylindrical casing string. The individual casing joints may be uniformly dimensioned such that each casing joint comprises a substantially identical length, outside diameter (OD), inside diameter (ID), and wall thickness, as well as other homogeneous characteristics, e.g. material strength (grade), weight, and end finish (e.g. threading, coupling, etc.). As such, a casing's length may be variable (e.g. depending on the number of casing joints), while the casing's diameter may be fixed (e.g. defined by the casing joints' uniform diameter which may range from about 2.5 to about 40 inches). Casing strings are typically assembled and installed in a piecemeal fashion by repeatedly coupling (e.g. threadably attaching) one casing joint to another casing joint and lowering the casing string into the wellbore, until the casing string has descended to a desired depth. Upon reaching the desired depth, the casing string may be fixed into place by conventional cementing techniques.
Many hydrocarbon-producing wells use a plurality of casings to isolate different formations at varying depths in the wellbore. For instance, a cased wellbore may comprise a surface casing for isolating a freshwater formation, an intermediate casing for isolating a potentially hazardous formation (e.g. a theft zone), and a production casing for isolating a producing formation (e.g. a pay zone). The wellbore's production casing may comprise a relatively small diameter pipe that is disposed within the intermediate casing and extends from the surface of the wellbore to a point at or below the targeted pay zone (e.g. to about the bottom of the wellbore). The wellbore's intermediate casing may comprise a somewhat larger diameter pipe that is disposed within the surface casing and extends from the surface of the wellbore to a point just below the hazardous formation (e.g. below the thief zone but above the pay zone). The wellbore's surface casing may comprise a relatively large diameter pipe that extends from the wellbore's surface to a point just below the freshwater formation. In some applications, the production casing may be dimensioned to accommodate production tubing and/or associated production equipment, while the intermediate casing may be dimensioned to accommodate the production casing, and the surface casing to accommodate the intermediate casing. In other applications, a wellbore's intermediate casing may have formerly been used as a “production casing” during the production of earlier pay zones, e.g. that have since been depleted. Hence, today's intermediate casing may have been yesterday's production casing. To avoid ambiguity, an interior casing may be referred to herein as a “child casing” and an exterior casing may be referred to herein as a “parent casing” (e.g. such that a child casing string is run within a parent casing string).
Once the child casing has been lowered to the desired depth within the parent casing, the child casing may be secured and/or fixed to the parent casing to stabilize the wellbore and prevent shifting of the child casing during subsequent drilling and/or production activities. Additionally, and to effectuate zonal isolation, the void and/or annulus formed between the child casing's outer wall and the parent casing's inner wall may be sealed to prevent “communication” between adjoining formations (i.e. to achieve zonal isolation). This void may be referred to herein as the casing casing annulus (CCA), and may serve a variety of functions during wellbore operations (e.g. providing an annular flow area to dispel cuttings and other debris).
An external casing packer (ECP) may be used alone or in conjunction with conventional cementing operations to seal the CCA and/or to fix the child casing string to the parent casing string. ECPs are typically composed of a mandrel encircled by a sealing element, but may also include various other components or features, e.g. packer shoes/collars, engagement assemblies, etc. The ECP's mandrel may be a specialty casing joint that is dimensioned similarly to the other casing joints within the child casing, and may be coupled directly into the child casing string such that the ECP comprises a link within the child casing string. The ECP may be strategically positioned within the child casing string such that the ECP can be set at the desired depth (e.g. when the ECP is said to be “on depth”) as the lower end of the child casing approaches the bottom of the wellbore. Setting the ECP may cause the ECP's sealing element to expand outwardly against the parent casing's inner wall, thereby sealingly fixing the child casing to the parent casing.
When used in conjunction with conventional cementing operations, setting of the ECP may be one step in the cementing operation, and may serve to stabilize the child casing during and/or after the cementing operation (e.g. during curing periods). The ECP may also provide a secondary sealing function in the event of a leak in the primary cement sheath formed in the CCA. Specifically, splintering and/or fracturing of the cement sheath surrounding the child casing may occur due to shifting/movement of the casings during and/or after cementing operations. For instance, variations in temperature and/or pressure may cause the casings to expand and/or contract, thereby compromising the cement-casing bond and causing a microannulus to form between the casing and the cement sheath. In extreme cases, the microannulus may substantially encircle the child casing's OD, thereby allowing potential communication between isolation zones (e.g. absent a secondary annular seal). Hence, the ECP's annular seal may be critical to zonal isolation in some applications.
Conventional ECPs may come in two varieties, namely; (1) external inflatable casing packers (EICPs) that employ inflatable sealing elements and (2) external mechanical casing (EMC) packers that employ compressible sealing elements. Conventional EICPs may actuate their sealing element by pumping hydraulic fluid into an inflatable bladder that encircles the EICP'S mandrel. Notably, the hydraulic fluid is typically pumped down the child casing's ID and through holes (e.g. perforations) in the EICP's mandrel wall. The EICP's porous mandrel wall may be difficult to reliably seal after the bladder has been fully inflated, with even properly sealed holes being weaker than the surrounding solid steel casing wall. Hence, holes in the EICP's mandrel wall may constitute weak spots in the child casing, and may be susceptible to leaks for the life of the well. Conventional EMC packers actuate their sealing element by exerting a vertical mechanical force (a setting force) on the sealing element, thereby longitudinally compressing the sealing element such that it laterally swells into the CCA. The setting force may be exerted on the EMC packer's sealing element by applying a longitudinally-compressive (down-hole) force to the child casing string after the EMC packer has engaged the parent casing. Hence, compressible sealing elements may be actuated via kinetic energy transferred vertically through the child casing string, rather than hydraulic energy transferred through perforations in the mandrel wall (e.g. such is the case with EICPs).
Before being “set”, conventional EMC packers must first engage an “internal upset” or landing in the parent casing (e.g. at or around the desired depth) that provides the necessary resistance to counteract the setting force and effectuate a compression of the EMC packer's sealing element. The “internal upset” may comprise a raised shoulder or some other restrictive protrusion that decreases the parent casing's ID and results in a diametrical constriction of the parent casing at or near the desired depth. Specifically, this diametrical constriction may capture a portion or component of the EMC packer (such as a lower packer shoe/collar), thereby “engaging” the EMC packer. Once captured, the lower packer shoe/collar may remain stationary in relation to the parent casing such that further displacement of the child casing causes the packer shoe to shear off (or otherwise become detached from the mandrel) and float along the mandrel's outer-wall. As the child casing is displaced further down-hole, the sealing element may be trapped between the floating lower packer shoe/collar and an upper packer shoe that remains fixed to the mandrel. Accordingly, the sealing element may become longitudinally-compressed as the distance between the upper and lower packer shoe decreases (e.g. in proportion to the child casing's displacement), causing the sealing element to swell outwardly into the CCA. Upon contacting the parent casing's inner wall, the sealing element may sealingly fix the child casing to the parent casing (at least presumably) for the life of the well.
Implementation of conventional EMC packers may have two functionally limiting characteristics, namely; (1) engaging of an “internal upset” in the parent casing and (2) being set “in compression”. Firstly, the “internal upset” along the parent casing's interior casing wall acts to diametrically constrict the parent casing's ID at or near the “on depth” point, thereby adversely affecting the parent casing's flow characteristics (e.g. casing and/or annular flow rates during earlier production periods and/or drilling operations). Additionally, the “internal upset” may necessitate the use of specialty wellbore equipment (e.g. modified drill-bits, centralizers, under-reamers, etc.) that are capable of extending past the constricted portion of the parent casing, which may add additional expense and/or complexity to subsequent down-hole operations. Another consequence of the “internal upset” engagement design is that the EMC packer itself may (by definition) be incapable of extending past the constricted portion of the parent casing, and hence may have only one possible pre-defined “on depth point” (e.g. conventional EMC packers can only be set at one depth). As a result, applications employing conventional EMC packers may lack flexibility and may be unable to adapt to changing wellbore conditions that prevent the child casing from being run to the bottom of the wellbore. For instance, uncased portions of the wellbore may swell, shift, and/or become partially filled with debris (e.g. cuttings, etc) before the child casing is run. In such cases, the child casing may be prevented from extending to the absolute bottom of the drilled wellbore, and instead may only run substantially down the wellbore (e.g. 20, 40, or 60 meters from the wellbore bottom). Because the EMC packer is positioned within the child casing string relatively early on (e.g. long before the child casings practical/achievable setting depth is known), well architects may base their strategic positioning of the EMC packer on projected wellbore conditions. Hence, aggressively positioned EMC packers (e.g. assuming good wellbore conditions) may not reach the parent casing's “internal upset”, while conservatively positioned EMC packers (e.g. assuming poor wellbore conditions) may reach the “internal upset” prematurely, thereby leaving a substantial portion of the wellbore “uncased”.
Secondly, conventional EMC packers are generally set “in compression” by applying a compressive (down-hole) force to the child casing after engagement of the EMC packer. Casings set “in compression” may have significantly lower collapse ratings than casings that are set “in tension” by applying an up-hole force. A casing's collapse rating may correspond to the minimum external pressure (i.e. the differential pressure acting from the outside to the inside of the casing) required to catastrophically deform the casing, and thus may be indicative of a characteristic of the casing's durability. Specifically, a casing's collapse pressure may be proportional to the casing's material strength, which may vary along the casing's length according to an axial stress exerted on the casing at different wellbore depths (e.g. due to a buoyancy differential). Usually, a casing's critical collapse pressure is determined at the bottommost casing joint (i.e. towards the bottom of the wellbore, where hydrostatic pressure is generally greatest), and hence reducing axial stress applied on the lower portion of the casing string may increase the casing's practical robustness. Setting the casing “in compression” generally increases axial stress at the bottom of the casing string, while setting the casing “in tension” generally relieves axial stress at the bottom of the casing string. Hence, casings that are set “in compression” may be less durable and/or more prone to collapse than casings that are set “in tension”. Additionally, compression-set EMC packers may require that the child casing have a minimum “string weight”, and hence may be ill-suited for some applications. Specifically, a tensional (up-hole) force is normally applied to the casing string to counteract the casing's “string-weight” (i.e. the gravitational force acting on the child casing), and hence the exertion of a compression (down-hole) force (e.g. to set the EMC packer) generally comprises “letting off” of the tension (e.g. rather than actually pushing down on the casing) such that the casing's own “string weight” is allowed to carry it down-hole. In other-words, the available compressive (down-hole) force may be limited by the casing's “string weight”, and thus relatively light casing strings may lack sufficient “string weight” to set some compression-set EMC packers. Thus, conventional (i.e. compression-set) EMC packers may not be suitable for applications in which the child casing's “string weight” is insufficient to compress their sealing elements.
Due to these and other limitations, a tension-set EMC packer whose engagement does not rely on an internal upset is needed.